CALGARY, ALBERTA–(Marketwired – May 9, 2013) – Baytex Energy Corp. (“Baytex”) (BTE.TO) (BTE) reports its operating and financial results for the three months ended March 31, 2013 (all amounts are in Canadian dollars unless otherwise noted).
Commenting on the results, James Bowzer, President and Chief Executive Officer of Baytex, said “Our operational execution remains on track. Production during the first quarter was consistent with our expectations and previous guidance and our 2013 drilling program is well underway with very encouraging results.”
- Produced 51,957 boe/d (87% liquids) in Q1/2013, consistent with previous guidance. Current production is approximately 56,000 boe/d, and full-year production guidance is unchanged at 56,000 to 58,000 boe/d;
- Generated funds from operations (“FFO”) of $101.8 million ($0.83 per basic share) in Q1/2013;
- Six horizontal oil wells encompassing 66 laterals were drilled in the Peace River area which, subsequent to the end of the quarter, established average 30-day peak production rates of approximately 800 bbl/d, with our best performing well averaging over 1,000 bbl/d. These are amongst the highest rate wells we have drilled in the Peace River area, and compare favorably to the average 30-day peak production rates we achieved in 2011 and 2012 of approximately 500 bbl/d;
- Drilled 58 net wells in our Lloydminster heavy oil area with a 98% success rate, and one thermal infill well at our Kerrobert steam-assisted gravity drainage project;
- Continued to progress our Peace River thermal project, receiving regulatory approval for the second thermal module; and
- Completed the sale of non-core Viking rights in the Kerrobert area for net proceeds of $42 million.
James Bowzer said: “We expect a continuing ramp up in our production in the coming quarters, which is likely to occur in a much stronger pricing environment for heavy oil. With current production of approximately 56,000 boe/d we remain confident in achieving our full-year production guidance.”
|Three Months Ended|
|March 31, 2013||December 31, 2012||March 31, 2012|
(thousands of Canadian dollars, except per common share amounts)
|Petroleum and natural gas sales||272,945||292,095||343,355|
|Funds from operations (1)||101,772||127,253||141,736|
|Per share – basic||0.83||1.05||1.20|
|Per share – diluted||0.82||1.04||1.18|
|Cash dividends declared (2)||56,449||55,043||55,559|
|Cash dividends declared per share||0.66||0.66||0.66|
|Per share – basic||0.08||0.26||0.36|
|Per share – diluted||0.08||0.26||0.36|
|Exploration and development||166,522||66,686||135,918|
|Proceeds from divestitures||(42,382||)||1,222||(3,568||)|
|Total oil and natural gas capital expenditures||124,140||198,483||134,686|
|Working capital deficiency||77,980||34,197||63,988|
|Total monetary debt (3)||686,162||599,826||690,742|
|Three Months Ended|
|March 31, 2013||December 31, 2012||March 31, 2012|
|Light oil and NGL (bbl/d)||7,920||7,739||7,565|
|Heavy oil (bbl/d)||37,486||40,257||38,353|
|Total oil and NGL (bbl/d)||45,406||47,996||45,918|
|Natural gas (mmcf/d)||39.3||42.3||45.1|
|Oil equivalent (boe/d @ 6:1) (4)||51,957||55,046||53,433|
|Average prices (before hedging)|
|WTI oil (US$/bbl)||94.37||88.18||102.93|
|WCS heavy oil (US$/bbl)||62.41||70.07||81.51|
|Edmonton par oil ($/bbl)||88.65||84.28||92.81|
|Baytex light oil and NGL ($/bbl)||76.72||72.02||81.99|
|Baytex heavy oil ($/bbl) (5)||53.47||54.58||65.89|
|Baytex total oil and NGL ($/bbl)||58.00||57.39||68.54|
|Baytex natural gas ($/mcf)||3.46||3.03||2.46|
|Baytex oil equivalent ($/boe)||52.89||52.37||60.98|
|CAD/USD noon rate at period end||1.0156||0.9949||0.9991|
|CAD/USD average rate for period||1.0089||0.9913||1.0003|
|COMMON SHARE INFORMATION|
|Share price (Cdn$)|
|Volume traded (thousands)||27,768||25,108||23,378|
|Share price (US$)|
|Volume traded (thousands)||3,369||3,567||4,488|
|Common shares outstanding (thousands)||122,874||121,868||118,905|
(1) Funds from operations is a non-GAAP measure that represents cash generated from operating activities adjusted for finance costs, changes in non-cash operating working capital and other operating items. Baytex’s funds from operations may not be comparable to other issuers. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends and capital investments. For a reconciliation of funds from operations to cash flow from operating activities, see Management’s Discussion and Analysis of the operating and financial results for the three months ended March 31, 2013.
(2) Cash dividends declared are net of DRIP participation.
(3) Total monetary debt is a non-GAAP measure which we define to be the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and long-term bank loan.
(4) Barrel of oil equivalent (“boe“) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(5) Heavy oil prices are net of blending costs.
Production averaged 51,957 boe/d (87% oil and NGL) during Q1/2013, as compared to 53,433 boe/d (86% oil and NGL) in Q1/2012 and 55,046 boe/d (87% oil and NGL) in Q4/2012. First quarter production was impacted by the timing of Peace River area development drilling activities, the suspension of production at the Kerrobert steam-assisted gravity drainage (“SAGD”) project to facilitate the drilling of an infill well, and the previously announced sale of non-core Viking rights in the Kerrobert area.
Our capital spending activity was weighted toward the latter portion of the first quarter with approximately half of the Q1/2013 capital expenditures incurred in March. Capital expenditures for exploration and development activities totaled $166.5 million for Q1/2013. During Q1/2013, Baytex participated in the drilling of 125 (110.0 net) wells with a 99% success rate.
Our 2013 production guidance remains at 56,000 to 58,000 boe/d with 2013 exploration and development capital expenditures forecast to be approximately $520 million. Current production is approximately 56,000 boe/d. Consistent with our budget expectations our production mix for 2013 is forecast to be 75% heavy oil, 14% light oil and NGL and 11% natural gas.
Wells Drilled – Three Months Ended March 31, 2013
|Crude Oil||Stratigraphic||Dry and|
|Primary||Thermal||Natural Gas||and Service||Abandoned||Total|
|Peace River area||6||6.0||–||–||–||–||30||30.0||–||–||36||36.0|
|Light oil, NGL and natural gas|
In Q1/2013, heavy oil production averaged 37,486 bbl/d. During Q1/2013, we drilled 74 (64.7 net) oil wells, 30 (30.0 net) service and stratigraphic test wells, and one (1.0 net) dry and abandoned well on our heavy oil properties with a success rate of 99%.
Production from our Peace River area properties averaged approximately 18,900 bbl/d in Q1/2013. At Peace River, we drilled 26 (26.0 net) stratigraphic test wells, four (4.0 net) service wells, and six (6.0 net) horizontal oil wells (encompassing a total of 66 laterals) in Q1/2013. Subsequent to the end of the quarter, these six horizontal oil wells established average 30-day peak production rates of approximately 800 bbl/d, with our best performing well averaging over 1,000 bbl/d. These are amongst the highest rate wells we have drilled to date in the Peace River area, and compare favourably to the average 30-day peak production rates we achieved in 2011 and 2012 of approximately 500 bbl/d. Current production from our Peace River properties is approximately 22,000 bbl/d. We plan to drill approximately 31 multi-lateral horizontal wells in the remainder of 2013.
Successful operations continued at our Cliffdale 10-well cyclic steam stimulation (“CSS”) module with Q1/2013 bitumen production averaging over 500 bbl/d. During Q1/2013, six wells received steam and commenced flowback operations. To-date, the Cliffdale project has demonstrated a cumulative steam-oil-ratio (“SOR”) of 2.4. The initial Cliffdale pilot well recently completed fourth cycle production operations, producing 118% more oil than the previous cycle and achieving a cycle SOR of 2.1. Fifth cycle steaming operations on this well commenced on April 4th with flowback operations scheduled for late Q2/2013. Regulatory approval for our new Cliffdale 15-well CSS module was received in late March. Facility construction is underway and drilling operations are scheduled to commence mid-year 2013.
In our Lloydminster heavy oil area, Q1/2013 drilling included 32 (25.2 net) horizontal oil wells, 35 (32.5 net) vertical oil wells, and one (1.0 net) dry and abandoned well. We also drilled one (1.0 net) thermal infill well in the Kerrobert SAGD project which will commence production in Q2/2013. We plan to drill approximately 55 net wells in the Lloydminster area in the remainder of 2013.
At Angling Lake, preliminary work continued on the Gemini SAGD project, including installation of groundwater monitoring wells and facility engineering and design activities. We expect to commence construction of the Gemini SAGD pilot facilities in Q2/2013.
Light Oil & Natural Gas
During Q1/2013, light oil, NGL and natural gas production averaged 14,471 boe/d, which was comprised of 7,920 bbl/d of light oil and NGL and 39.3 mmcf/d of natural gas. This compared to Q1/2012 light oil and NGL production of 15,082 boe/d and Q4/2012 production of 14,789 boe/d.
In our Bakken/Three Forks play in North Dakota, we drilled seven (3.0 net) operated horizontal oil wells and fracture-stimulated five (1.5 net) operated wells in Q1/2013. During Q1/2013, two Baytex-operated wells on 1,280-acre spacing established average 30-day peak production rates of approximately 375 boe/d. We plan to drill approximately 13 (5.5 net) wells on our Bakken/Three Forks play in North Dakota in the remainder of 2013. We also drilled three (3.0 net) Bakken/Three Forks wells in south Saskatchewan in the first quarter, one of which received a multi-stage fracture treatment in the quarter.
In Q1/2013, we completed the previously disclosed disposition of approximately 22,000 net acres of non-core Viking rights in the Kerrobert area of southwest Saskatchewan, which included production of approximately 100 bbl/d, for net proceeds of $42 million.
We generated FFO of $101.8 million ($0.83 per basic share) in Q1/2013, compared to $141.7 million in Q1/2012 and $127.3 million in Q4/2012. The decrease relative to Q1/2012 was the result of lower realized commodity prices and lower sales volumes as well as higher operating expenses, while the decrease relative to Q4/2012 was largely the result of lower sales volumes and higher operating expenses.
The average WTI price for Q1/2013 was US$94.37/bbl, an 8% decrease from Q1/2012 and a 7% increase from Q4/2012. We received an average oil and NGL price of $58.00/bbl in Q1/2013 (inclusive of our physical hedging gains), a decrease of 15% from $68.54/bbl in Q1/2012 and an increase of 1% from $57.39/bbl in Q4/2012. Our realized oil prices include the impact of sales to new markets by rail, which averaged approximately 12,000 bbl/d of heavy oil for Q1/2013, as compared to 7,500 bbl/d for full-year 2012.
The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged 34% in Q1/2013, as compared to 21% in both Q1/2012 and Q4/2012. Factors that caused heavy oil differentials to widen included apportionment on Canadian heavy oil export pipelines, reduced refinery runs due to normal seasonality and both planned and unplanned refinery maintenance.
Market conditions have improved recently with forward markets indicating a WCS average differential of approximately 20% for Q2/2013. Railways are continuing to play an expanding role in alleviating transportation constraints that limit the ability of Canadian crude supply to access new markets, including the U.S. Gulf Coast, which represents the largest North American heavy oil market.
In this volatile differential environment, Baytex continues to actively hedge its exposure to commodity prices and foreign exchange rates. For Q2/2013 to Q4/2013, we have entered into hedges on approximately 44% of our WTI exposure at a fixed price of US$98.10/bbl, 42% of our exposure to WCS heavy oil differentials through a combination of long term physical supply contracts and rail delivery, 45% of our natural gas price exposure, and 39% of our exposure to currency movements between the U.S. and Canadian dollars. Details of our hedging contracts are contained in the notes to our financial statements.
As part of our hedging program, we are focused on opportunities to further mitigate our exposure to WCS price differentials by transporting crude oil to higher value markets by railway. For Q2/2013, we expect to deliver approximately 16,000-17,000 bbl/d of our heavy oil volumes by rail, and we continue to explore opportunities for additional rail deliveries.
Production and operating expenses were $13.95/boe in the first quarter of 2013. These costs were higher than prior periods due to lower production volumes, higher than normal snow removal costs, increased labor costs, and higher energy input costs. We expect production and operating expenses to average approximately $12.00-$12.50/boe for the balance of 2013.
Royalty rates in Q1/2013 were approximately 18.3% of sales revenues before sales of purchased condensate. We expect royalty rates to average approximately 20-21% for full-year 2013 as a result of certain oil sands projects reaching payout and farm-in agreements.
Total monetary debt at the end of Q1/2013 was $686 million representing a debt-to-FFO ratio of 1.4 times based on FFO over the trailing twelve-month period. At the end of the quarter, Baytex had over $540 million in available undrawn credit facilities and no long term debt maturities until 2021. Proceeds from the sale of the Kerrobert Viking rights have been used to repay amounts outstanding on our credit facilities. Baytex is currently finalizing documentations with our lending syndicate to increase the amount of our credit facilities by $150 million to $850 million and to extend the maximum term of the facilities by one year to four years. We expect to have these facilities available by the end of the second quarter.
Our unaudited interim condensed consolidated financial statements for the three months ended March 31, 2013 and related Management’s Discussion and Analysis of the operating and financial results can be accessed immediately on our website at www.baytex.ab.ca and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.
Conference Call Today 9:00 a.m. MST (11:00 a.m. EST)
Baytex will host a conference call today, May 9, 2013, starting at 9:00am MST (11:00am EST). To participate, please dial 416-340-9432 or toll free in North America 1-888-340-9761 and toll free international 800-2787-2090. Alternatively, to listen to the conference call online, please enterhttp://www.gowebcasting.com/4293 in your web browser.
An archived recording of the conference call will be available until May 16, 2013 by dialing toll free 1-800-408-3053 within North America (Toronto local dial 905-694-9451, International toll free 800-3366-3052) and entering reservation code 1399715. The conference call will also be archived on the Baytex website at www.baytex.ab.ca.
Advisory Regarding Forward-Looking Statements
In the interest of providing Baytex’s shareholders and potential investors with information regarding Baytex, including management’s assessment of Baytex’s future plans and operations, certain statements in this press release are “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 and “forward-looking information” within the meaning of applicable Canadian securities legislation (collectively, “forward-looking statements”). In some cases, forward-looking statements can be identified by terminology such as “anticipate”, “believe”, “continue”, “could”, “estimate”, “expect”, “forecast”, “intend”, “may”, “objective”, “ongoing”, “outlook”, “potential”, “project”, “plan”, “should”, “target”, “would”, “will” or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.
Specifically, this press release contains forward-looking statements relating to: our average production rate for 2013; our exploration and development capital expenditures for 2013; our production mix for 2013; development plans for our properties, including the number of wells to be drilled in the remainder of 2013 and, in some cases, when such wells will commence production; initial production rates from wells drilled; our Peace River heavy oil area, including our assessment of the productivity of recently drilled horizontal wells; our Cliffdale cyclic steam stimulation project, including our assessment of the steam and flowback operations and the cumulative steam-oil ratio for the initial 10-well module, our plan for a second module and the timing of drilling the wells for the second module; our plans for a steam-assisted gravity drainage pilot project at Angling Lake, including the timing of construction of the pilot facilities; the outlook for Canadian heavy oil prices and the pricing differential between Canadian heavy oil and West Texas Intermediate light oil; the ability to access the U.S. Gulf Coast market by transporting crude oil on railways; the existence, operation and strategy of our risk management program for commodity prices, heavy oil differentials and interest and foreign exchange rates; our ability to mitigate our exposure to heavy oil price differentials by transporting our crude oil to market by railways; the volume of heavy oil to be transported to market on railways for the balance of 2013; our average royalty rate for full-year 2013; our production and operating expenses per unit of production for the balance of the 2013 year; our debt-to-FFO ratio; the amount of our undrawn credit facilities at March 31, 2013; our liquidity and financial capacity; and our plan to amend our credit facilities to increase the amount and the term thereof and the timing of completing such amendments. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, the Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures and our prevailing financial circumstances at the time.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the receipt, in a timely manner, of regulatory and other required approvals; the availability and cost of labour and other industry services; the amount of future cash dividends that we intend to pay; interest and foreign exchange rates; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes. Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; uncertainties in the credit markets may restrict the availability of credit or increase the cost of borrowing; refinancing risk for existing debt and debt service costs; access to external sources of capital; third party credit risk; a downgrade of our credit ratings; risks associated with the exploitation of our properties and our ability to acquire reserves; increases in operating costs; changes in government regulations that affect the oil and gas industry; changes to royalty or mineral/severance tax regimes; risks relating to hydraulic fracturing; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; risks
associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with properties operated by third parties; risks associated with delays in business operations; risks associated with the marketing of our petroleum and natural gas production; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; expansion of our operations; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in environmental, health and safety regulations; the implementation of strategies for reducing greenhouse gases; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; the activities of our operating entities and their key personnel and information systems; depletion of our reserves; risks associated with securing and maintaining title to our properties; seasonal weather patterns; our permitted investments; access to technological advances; changes in the demand for oil and natural gas products; involvement in legal, regulatory and tax proceedings; the failure of third parties to comply with confidentiality agreements; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management’s Discussion and Analysis for the year ended December 31, 2012, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.
There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.
Non-GAAP Financial Measures
Funds from operations is not a measurement based on Generally Accepted Accounting Principles (“GAAP”) in Canada, but is a financial term commonly used in the oil and gas industry. Funds from operations represents cash generated from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. Baytex’s determination of funds from operations may not be comparable with the calculation of similar measures for other entities. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.
Total monetary debt is not a measurement based on GAAP in Canada. Baytex defines total monetary debt as the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives)), the principal amount of long-term debt and long-term bank loans. Baytex believes that this measure assists in providing a more complete understanding of its cash liabilities.
Baytex Energy Corp.
Baytex Energy Corp. is a dividend-paying oil and gas corporation based in Calgary, Alberta. The company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Williston Basin in the United States. Approximately 89% of Baytex’s production is weighted toward crude oil. Baytex pays a monthly dividend on its common shares which are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.